The application of syngas conversion and purification after a gasification process can be used for integrated gasification combined cycle (IGCC) power plants for electricity production from coal. It can also be used for gasification-based power plants that produce multiple products such as hydrogen and electricity from coal, and it is also useful for plants that include carbon dioxide separation. It is also applicable to purification of other hydrocarbon-derived syngas that can be used for electricity production or power, including syngas derived from natural gas, heavy oil, biomass and other sulfur-containing carbon fuels.
The commercialization of known “coal-to-hydrogen (H2) and electricity” technologies (IGCC power plants or coal gasification-based power plants) has been hampered by the high capital costs associated with removing the most significant impurities, such as sulfur, present in coal. The stringent purity requirements for hydrogen fuel and the fuel specifications for the gas turbine are generally satisfied using a series of clean-up unit operations, which facilitate carbon monoxide (CO) conversion, sulfur removal, and final gas polishing. In addition, carbon dioxide (CO2) removal is desirable in situations where CO2 is captured for sequestration. The cleaned syngas produced can be sent to a combined cycle plant to produce electricity. Because syngas is a feedstock for manufacturing chemical and fuels, it can also be used in a power plant that integrates a combined cycle power plant and chemical reactors for power of electricity and chemical products. The chemical products can include hydrogen, ammonia, methanol, dimethyl ether and Fischer-Tropsch gasoline and diesel fuels. The CO2 rich stream can be compressed and sent to sequestration.
Some known syngas clean-up technologies focus on removing each impurity in a separate unit operation. In a system configured to capture CO2, raw fuel gas exiting the gasifier is cooled and cleaned of particulate before being routed to a series of sulfur removal units and water-gas-shift (WGS) reactors. Those unit operations convert CO and H2O present in the syngas to CO2 and H2, thereby concentrating it in the high-pressure raw fuel gas stream. Once concentrated, CO2 and sulfur present in the stream can be removed using low temperature liquid-based absorption processes. The CO2 is recovered from the absorption process in a manner that results in at least a fraction of the CO2 being recovered at a lower pressure than the feed to the liquid absorber unit. CO2 is then dried and compressed to supercritical conditions for pipeline transport. Part of the clean fuel gas from the liquid-based absorber unit, now rich in H2 and also containing the unreacted CO from the WGS reactor, is either fired directly in a gas turbine, or used in other power systems. Waste heat is recovered from the process and used to raise steam to feed to a steam turbine. Part of the clean stream can be purified further to produce fuel grade H2 product. However, because of the different operating requirements and parameters of each unit, known clean-up technologies may be expensive. Moreover, because of the large number of unit operations used, known clean-up technologies generally require large footprints within a plant. For example, at least some known units have auxiliary requirements for solvent regeneration and pollutant recovery. Known liquid absorption units for CO2 and H2S involve low temperature processes that require the gas stream to be cooled resulting into energy loss and lower efficiency.
Membranes are selectively permeable barriers that can be used to separate gases and can be used in the syngas clean-up process to separate the syngas into a fuel-rich stream that can be used to generate electricity, and a CO2-rich retentate stream to enable “carbon capture”. The use of a membrane for carbon capture can involve the selective permeation of CO2 through the membrane, separating it from the rest of the gas stream, or can involve the selective permeation of hydrogen, the primary fuel gas. In an ideal situation for some power generation systems, gas separation is carried out at high temperature and pressure, so as to minimize the necessity for compressing the CO2 prior to sequestration.
A key challenge associated with hydrogen-selective membranes is the difficulty in recovering all of the fuel components of the shifted syngas stream. WGS reactors do not convert all of the CO in the raw syngas to CO2. Membrane systems are typically suitable for rough stage cuts, and very large membrane areas are required for high recovery rates. Moreover, known hydrogen-selective membranes are not permeable to carbon monoxide and therefore are unable to transfer this gas to the fuel-rich permeate stream. Collectively, the residual H2 and CO in the membrane retentate stream is referred to as the “slip.” Therefore, IGCC plant designs using hydrogen-selective membranes to separate CO2 require additional unit operations to ensure the overall thermal efficiency of the plant is not overly degraded by the H2 and CO slip from the membrane separation system.